Method for improving oil sands hot water extraction process

ABSTRACT

A method for increasing the bitumen extraction efficiency in the hot water oil sands extraction process. A volume of gaseous carbon dioxide is added into the oil sands slurry that is being transported through a hydrotransport pipeline from the oil sands mining site to the bitumen extraction plant at a position where the oil sands has been conditioned to a desired degree. Carbon dioxide is injected into the slurry under elevated pressure through a gas distribution device while the hydraulic pressure in the pipeline is maintained at an elevated pressure. After the carbon dioxide-bearing oil sands slurry is fed into the separation vessel, a part of the carbon dioxide is recovered for reinjection.

BACKGROUND OF THE INVENTION

The present invention relates to a process for adding carbon dioxide ina hydrotransport pipeline through which oil sands slurry is transportedto an extraction plant in order to improve bitumen recovery efficiency.

Hot water extraction process is the most frequently employed techniqueto recover bitumen from surface mined oil sands. Due to the highcapacity and low operating cost of modern hot water extraction processfor oil sands and other mined oil bearing formations, other alternativeprocesses are not likely to replace this process in the near future. Ina conventional hot water extraction process, before bitumen is extractedin a separation vessel, a mixture of oil sand, hot process water, andextraction additive, normally caustic reagent such as sodium hydroxideor sodium carbonate, is conditioned in a large tumbler or drum byintense mechanical agitation for a predetermined period to achieve adesired separation degree of bitumen from sand grains and entraining ofair bubbles in the slurry. This modern hot water extraction process,which is developed from the conventional hot water process, transportsoil sand, hot process water and extraction additives to a separationvessel in a pipeline wherein conditioning of oil sand is achieved duringtransportation. This method, called hydrotransport, is one of the mostimportant developments in the oil sands surface mining industry since itgreatly increases treatment capacity of the oil sands extraction plantand reduces energy cost.

U.S. Pat. No. 5,264,118 describes a pipeline conditioning process formined oil sands wherein oil sands is transported with hot water andsodium hydroxide via a pipeline of sufficient length. During theconditioning process, with assistance of sodium hydroxide, bitumen isliberated from sand grains and entrained air facilitates subsequentaeration of the bitumen. The conditioned oil sands slurry is fed to agravity separation vessel, known as primary separation vessel (PSV), tosettle into three layers, bitumen froth, middlings, and sand underquiescent conditions. The middlings, which is normally processed in asecondary separation vessel, is a mixture of buoyant bitumen, clay andwater. In one embodiment of that invention achieving more 90% totalbitumen recovery efficiency, the pipeline has a length of 2.5 kilometersto achieve a desired extraction efficiency for a mixture of 50 to 70% byweight of oil sands, 50 to 30% by weight of hot water, and less than0.05% by weight of sodium hydroxide at a temperature between 40° C. to70° C. The residence time of oil sands slurry in the pipeline is about14 minutes.

It is believed that bitumen flecks tend to coalesce and attach or coatto the air bubbles entrained in the slurry. Because the amount of theentrained air is an important factor for oil sands conditioning in thehydrotransport pipeline, a more effective method of adding air into oilsands slurry can significantly improve the overall bitumen extractionefficiency. A device, cyclofeeder, described in Canadian Patent No.2,029,795 and U.S. Pat. No. 5,039,227, can simultaneously entrain airinto the slurry when it is mixing oil sands with hot water. In U.S. Pat.No. 6,007,708, the aeration effects by gas bubbles are enhanced byinjecting compressed air in the hydrotransport pipeline to improve thebitumen extraction efficiency at a relatively low conditioningtemperature. The drawback of this process is that the extracted bitumencontains relatively high concentration of impurities due to bitumen'shigh viscosity at low temperature and incomplete separation of bitumenfrom sand grains. The volume ratio of air to slurry can be up to 2.5:1and the overall bitumen recovery efficiency can be as high as 98%.Another example to explore the separation and floatation effects of gasbubbling is described in Canadian Patent No. 2,703,835, in which the oilsands and hot water mixture is treated in a closed vessel by cycliccompression and decompression of compressed air or carbon dioxide in thevessel. This method can achieve more than 90% bitumen extractionefficiency for tar sands or oil sands from different countries withoutthe assistant of caustic reagent and does not generate middlings. Themajor drawback of this method is that the extraction capacity of adevice is limited by the vessel size due to the high construction costof a large pressure vessel. Also, International Patent Application No.WO 2005/123608A1 teaches a method of adding hydrogen peroxide into aconditioned mixture of oil sands and hot water. The oxygen bubblesgenerated through decomposition of hydrogen peroxide may accelerateseparation and floatation of bitumen. An obvious drawback of thisprocess is that the high purchasing price of hydrogen peroxide makesthis process less competitive. Also, oxygen, which is not preferred inthe subsequent bitumen upgrading processes, may have been added intobitumen structures.

Caustic reagent is normally required to improve the conditioning effectsin the hot water extraction process. However, addition of causticreagent such as sodium hydroxide has many drawbacks. The major problemis that caustic reagent will cause emulsification of released bitumen inwater and suspension of fine particles in the aqueous phase. Thoseeffects greatly reduce the overall bitumen extraction efficiency andcause serious environmental problems when the process water is beingdisposed.

Another problem is generation of large amount of middlings in theseparation vessel. Although most bitumen contained in the middlings andtailings can be recovered in the subsequent extraction processes,improving the primary separation vessel's froth production and qualityis the most effective way to reduce the overall operating cost. CanadianPatent 2,004,352 has addressed these problems by replacing the causticreagent by kerosene and methyl-isobutyl carbinol. This method also has aproblem of high operating cost due to usage of large amount ofchemicals. In order to treat the process water from the hot waterextraction process that contains suspended solids and emulsified bitumenat a high pH level by the caustic reagent, Canadian Patent 1,022,098discloses a method to break the emulsion to recover additional bitumenand accelerate precipitation of the suspended solids throughneutralizing the process water by addition of inorganic acids and carbondioxide. It has been recognized that neutralizing the process water topH at around 7 by an inorganic acid is not sufficient for emulsionbreaking. The purpose of utilizing inorganic acid to adjust water pH isto facilitate the emulsion breaking effect of carbon dioxide sincecarbon dioxide is not a strong acid for pH adjustment. But the additionof inorganic acid generates permanent unwanted salt in the process waterand limits reuse of the process water.

It is noticed that after bitumen is separated from sand grains andbitumen droplets are formed with the help of the caustic reagent, thebasic condition is not necessarily to be maintained in the separationvessel for formation of froth. On the contrary, the caustic conditioncan cause emulsification of bitumen in hot water and generate largeamount of middlings. De-emulsification of the emulsion, such as reducingpH of the process water or adding flocculent, can improve the totalrecovery ratio of bitumen in the primary separation vessel. Since carbondioxide is a good reagent to neutralize process water, using carbondioxide to adjust oil sands slurry's pH level is a practical measure. Toachieve the emulsion breaking effect, a lower pH value by dissolvingmore carbon dioxide under elevated pressure may be required. Inaddition, since noticeable amount of carbon dioxide is dissolved inbitumen under elevated pressure, pressure drop in the primary separationvessel can significantly increase bitumen's buoyancy through expansionof the bitumen droplets. Also, reduction of emulsified bitumen in waterand increase of bitumen's buoyancy can prevent generation of largeamount of middlings.

So the operating costs for middlings treatment and subsequent processwater treatment can be reduced. Compared to adjusting water pH usingassistant inorganic acid, which is used in other methods because carbondioxide is not sufficient for pH adjustment in a non pressure vessel ora low pressure vessel, using carbon dioxide will not permanentlyincrease the water salt concentration since the product of carbondioxide and sodium hydroxide is sodium carbonate, which is also used asa caustic reagent for oil sands extraction in the how water extractionprocess. However, pressurizing the primary separation vessel in a largeroil sands extraction plant is not practical because of the highconstruction cost of a large pressure vessel. Injecting carbon dioxidein the hydrotransport pipeline is a more practical method for adjustingthe oil sands slurry's pH.

SUMMARY OF THE INVENTION

A method for recovering bitumen comprising adding carbon dioxide to apipeline containing an oil-bearing formation being transported isdisclosed.

The invention aims to improve the bitumen recovery efficiency in theprimary separation vessel by simultaneous improvement of the aerationeffect and reduction of the bitumen emulsification degree. Thisinvention can be applied, but is not limited to, improving the oilextraction of oil sands and other oil bearing formation in a hot waterextraction process. The same method can be applied to remediation ofcontaminated soil, treatment of waste water, and mine floatation inorder to improve treatment efficiency.

In one embodiment of the invention, carbon dioxide is injected into thehydrotransport pipeline, through which oil sands slurry is conditionedwhen being transported from a mining site to an extraction plant, at aposition where the oil sands have been conditioned to a desired degree.The pH of the oil sand slurry after dissolving carbon dioxide in theprocess water, which can be measured by a set of pH probes installed onthe pipeline, is adjusted to a value below 8 and preferably below 7 bycontrolling the carbon dioxide's flow rate. Since the volumetric ratioof the dissolved carbon dioxide to water is mainly decided by the watertemperature and the pressure, the hydraulic pressure in the pipeline ismaintained at an elevated pressure to guarantee that a desired amount ofcarbon dioxide is dissolved in the process water. Also, some otheraspects such as the salt concentration and alkalinity of water that canaffect the equilibrant carbon dioxide concentration in the aqueous phaseare taken into account.

In the pipeline in which carbon dioxide is being dissolved, thehydraulic pressure is maintained between 1.1 bars to 20 bars for thepurpose of dissolving more carbon dioxide and a boosting pump isinstalled if necessary. The pressure used in describing the invention isabsolute pressure. The improvement of bitumen extraction is alsofacilitated by other synergetic effects due to injection of carbondioxide, such as aeration and gas bubble floatation effect in theseparation vessel and higher buoyancy of the bitumen droplets.Therefore, by maintaining an elevated hydraulic pressure in thepipeline, the volumetric flow rate ratio of carbon dioxide to theprocess water in the hydrotransport pipeline is controlled from 0.2:1 to15:1. The gas volume used in this invention is its volume under standardcondition. Adding carbon dioxide into the hydrotransport pipeline can beachieved by one venturi device or other gas dissolving devices such as aset of nozzles. The pressure of carbon dioxide is maintained at apressure higher than the hydraulic pressure in the hydrotransportpipeline for the purpose of injection at a high gas flow rate,preferably between 1.5 bars to 21 bars.

To adjust the dissolved carbon dioxide concentration in the oil sandsslurry, a fresh water stream can be optionally mixed with the oil sandsslurry flow prior to being fed into the primary separation tank. Thevolumetric mixing ratio of the fresh water to the oil sands slurry isfrom 0:1 to 3:1. The water's temperature can be controlled from 20° C.to 120° C. Also, the invention comprises a carbon dioxide recyclingpipeline to recover the released carbon dioxide from the oil sandsslurry in the primary separation vessel, in which the operating pressureis at ambient pressure or a pressure lower than the hydraulic pressurein the pipeline. The recovered carbon dioxide can be stored in a carbondioxide storage tank or be injected into another hydrotransport pipelinein parallel operation with or without treatment, depending on theinsoluble gas concentration in it. Since a part of carbon dioxide thatdissolved in the process water under ambient pressure is notrecoverable, supplementary carbon dioxide is provided to maintain thecarbon dioxide flow rate. To reduce corrosion of equipment caused by thedissolved carbon dioxide in water and to recycle process water forcontinuous conditioning of oil sands in the hydrotransport pipelineunder basic conditions, the process water recovered from the separationvessel is aerated by air or other inert gases such as nitrogen, methane,carbon monoxide and argon, or is heated to an elevated temperature byinjection of steam.

BRIEF DESCRIPTION OF THE DRAWINGS

The FIGURE is a schematic process flow diagram showing injection ofcarbon dioxide in the hydrotransport pipeline in the oil sands hot waterextraction process.

DETAILED DESCRIPTION OF THE INVENTION

As shown in the schematic process flow diagram, carbon dioxide fromcarbon dioxide tank A is injected into the hydrotransport pipeline 3,which transports oil sands slurry to an extraction plant, through line2, at a position where the oil sands slurry has been conditioned to adesired degree higher than 50%, preferably higher than 80%, and morepreferably higher than 90%, that the basic condition is no longerrequired for liberation of bitumen from sand grains. The carbon dioxidemay be supplied to the carbon dioxide tank A through line 1 from atrailer or other ready source of carbon dioxide. In order to neutralizethe slurry by dissolving a desired amount of carbon dioxide in theprocess water, the hydrotransport pipeline 3 pressure for carbon dioxideinjection is maintained at an elevated pressure from 1.2 bars to 21bars, preferably from 3 bars to 10 bars. The pH of the oil sands slurryin the hydrotransport pipeline 3, which can be measured by a set of pHprobes installed on the hydrotransport pipeline 3, is adjusted to alevel below 8 and preferably below 7 by controlling the carbon dioxideflow rate.

Carbon dioxide can be directly injected in oil sand slurry through a setof nozzles or a gas disperser such as a venturi device. Although it isnot necessary that all carbon dioxide be dissolved in the oil sandsslurry since existence of gas bubbles in the slurry improvesconditioning effect, an elevated pressure is maintained in the pipelineto keep as much as possible of carbon dioxide is dissolved in the oilsands slurry. The pressure in the hydrotransport pipeline 3 behind thecarbon dioxide injection point is maintained between 1.1 bars to 20bars, preferably between 2 bars to 10 bars. The length of thehydrotransport pipeline 3 for dissolving carbon dioxide and theresidence time of oil sands slurry in the hydrotransport pipeline 3 forbreaking emulsion are decided by the hydraulic pressure, the slurry'spH, amount of impurities in water such as suspended fine particles,alkalinity of the process water and the emulsification degree of bitumenin water, preferably from 1 meter to 2 kilometers, more preferably from100 meters to 1 kilometer. The volumetric flow rate ratio of carbondioxide to the process water in the hydrotransport pipeline 3 iscontrolled from 0.2:1 to 15:1, preferably from 0.5:1 to 10:1.

The oil sands slurry is fed into the hydrotransport pipeline 3 frommixer B through line 12. The oil sands slurry is fed into mixer Bthrough line 9; hot water is also fed into the mixer B through line 8 toline 11 and additives such as sodium hydroxide or sodium carbonate arealso fed into the mixer B through line 10. The mixer B is typically acyclofeeder. The hot water in line 8 can also be directed immediately orin addition to its transport into line 11 and mixer B, directly into thehydrotransport pipeline 3.

Before the carbon dioxide-bearing oil sands slurry is added into theprimary separation vessel C or other separation vessels, the oil sandsslurry flow in hydrotransport pipeline 3 is merged with a fresh waterstream through line 8 to adjust the volumetric ratio of gas to water forthe purpose of optimizing the gas flotation effect for bitumen in thevessel. The mixing volumetric flow rate ratio of the fresh water to oilsands slurry is controlled from 0:1 to 3:1, preferably from 0.1:1 to1:1. And the water's temperature is controlled from 20° C. to 120° C.After dilution, the oil sands slurry is fed into the separation vessel Cthough a pressure reducing device such as a nozzle or a valve.

In this embodiment, the primary separation vessel C is operated underambient pressure or a pressure lower than the hydraulic pressure in thehydrotransport pipeline 3. Therefore, a part of carbon dioxide dissolvedin water and bitumen transforms into bubbles after pressure drop toprovide additional bitumen separation and flotation effects in theseparation vessel. Gaseous carbon dioxide in the primary vessel'soverhead space can be recycled through a carbon dioxide recoverypipeline 7 to a carbon dioxide storage tank A or be directly injectedinto another hydrotransport pipeline in parallel operation, not shown.The recycled carbon dioxide may contain air entrained in oil sandsduring conditioning, so the carbon dioxide is diluted by fresh carbondioxide or be treated by other measures to control the insoluble gasconcentration in it if it is necessary. The overall impuritiesconcentration in carbon dioxide is controlled lower than 20%, preferablyless than 10%, and more preferably less than 5% by volume. Also, therecovered carbon can be used for other purposes.

The primary separation vessel C is typically a large, conical-bottomed,cylindrical vessel. The primary separation vessel C will separate theoil sand slurry that is fed through hydrotransport pipeline 3 into threedistinct components plus excess carbon dioxide that may be present inthe oil sand slurry. The sand and water will exit through the bottom ofthe primary separation vessel C through the bottom line 6 which can betreated and returned to where the oil sand was originally derived fromor transported for other disposal means. The middlings which areseparated in the primary separation vessel C are removed through line 5and froth is removed through line 4. As mentioned previously, carbondioxide is recovered and recycled through line 7 back to the carbondioxide storage tank A where it can be used for injection into thehydrotransport pipeline 3.

Since the process water recovered through line 6 from the separationvessel C contains dissolved carbon dioxide, which may cause corrosion ofthe equipments and pipelines and require additional caustic reagent tocondition the oil sands when the recovered water is to be reused, theprocess water is aerated by air or other inert gases such as nitrogen,methane, carbon monoxide and argon, or is heated to a higher temperatureby injection of steam or other heating methods before reuse.

In another embodiment, carbon dioxide is mixed with a fresh water streambefore being added in the oil sands slurry. The purpose of mixing thefresh water with carbon dioxide is to make carbon dioxide partiallydissolved in water at a pressure higher than the pressure in thepipeline. The fresh water's temperature can be higher or lower than theoil sands slurry's temperature transported in the pipeline. Thevolumetric flow rate ratio of the carbon dioxide to fresh water iscontrolled from 1:0 to 20:1. The water's temperature is controlled from1° C. to 100° C.

In another further embodiment, the carbon dioxide is injected into thehydrotransport pipeline at several points and the distance between twoadjacent points is from 1 meter to 500 meters, more likely from 10 meterto 200 meters. The number of injection points is from 2 to 20 and thecarbon dioxide's injection rate at different injection points can be thesame, close to or different at each injection point. The flow rate ratioof the overall of carbon dioxide to the process water in the oil sandsslurry is from 0.2:1 to 15:1, preferably from 0.5:1 to 10:1.

While this invention has been described with respect to particularembodiments thereof, it is apparent that numerous other forms andmodifications of the invention will be obvious to those skilled in theart. The appended claims in this invention generally should be construedto cover all such obvious forms and modifications which are within thetrue spirit and scope of the invention.

1. A method for recovering bitumen comprising adding carbon dioxide to apipeline containing an oil-bearing formation being transported.
 2. Themethod as claimed in claim 1 wherein said oil-bearing formation is beingtransported to a processing plant.
 3. The method as claimed in claim 1wherein said oil-bearing formation is selected from the group consistingof an oil sands slurry, tar sands slurry and oil-contaminated soilslurry.
 4. The method as claimed in claim 1 wherein the volumetric flowrate ratio of said carbon dioxide to process water in said pipeline iscontrolled from 0.2:1 to 15:1.
 5. The method as claimed in claim 1wherein the volumetric flow rate ratio of said carbon dioxide to processwater in said pipeline is controlled from 0.5:1 to 10:1.
 6. The methodas claimed in claim 1 wherein said carbon dioxide injection pressure ismaintained at a pressure from 1.2 bars to 21 bars.
 7. The method asclaimed in claim 1 wherein said carbon dioxide injection pressure ismaintained at a pressure from 3 bars to 10 bars.
 8. The method asclaimed in claim 1 wherein the pressure in the pipeline behind thecarbon dioxide injection point is maintained between 1.1 bars to 20bars.
 9. The method as claimed in claim 1 wherein the pressure in thepipeline behind the carbon dioxide injection point is maintained between2 bars to 10 bars.
 10. The method as claimed in claim 4 wherein thepressure is maintained by a boost pump.
 11. The method as claimed inclaim 3 wherein the pH of the oil sands slurry in the pipeline isadjusted to a level below
 8. 12. The method as claimed in claim 11wherein the pH of the oil sands slurry is adjusted by controlling thecarbon dioxide flow rate.
 13. The method as claimed in claim 11 whereinthe pH is measured by a set of pH probes installed on the pipeline. 14.The method as claimed in claim 1 wherein said carbon dioxide is injectedin the pipeline at a point where the oil-bearing formation has beenconditioned to a degree higher than 50%.
 15. The method as claimed inclaim 1 wherein said carbon dioxide is injected in the pipeline at apoint where the oil-bearing formation has been conditioned to a degreehigher than 80%.
 16. The method as claimed in claim 1 wherein the lengthof said pipeline is from 1 meter to 2 kilometers.
 17. The method asclaimed in claim 16 wherein the length of said pipeline is from 100meters to 1 kilometer.
 18. The method as claimed in claim 1 wherein theoil-bearing formation flow is merged with a fresh water stream before itis fed to a separation vessel and the volumetric flow rate ratio of thefresh water to oil-bearing formation is from 0:1 to 3:1.
 19. The methodas claimed in claim 18 wherein the volumetric flow rate ratio of thefresh water to oil-bearing formation is from 0.1:1 to 1:1.
 20. Themethod as claimed in claim 1 wherein said carbon dioxide is directlyinjected into said oil-bearing formation through a device selected fromthe group consisting of nozzles and a venturi device.
 21. The method asclaimed in claim 18 wherein the temperature of the water is from 20° C.to 120° C.
 22. The method as claimed in claim 1 wherein the carbondioxide-bearing oil-bearing formation is fed into said separation vesselthrough a device selected from the group consisting of a nozzle andpressure reducing.
 23. The method as claimed in claim 22 wherein saidseparation vessel is operated under ambient pressure.
 24. The method asclaimed in claim 23 wherein said separation vessel is operated at apressure lower than the pressure in said hydrotransport pipeline. 25.The method as claimed in claim 22 wherein gaseous carbon dioxide in theseparation vessel is recycled through a carbon dioxide recovery pipelineto a carbon dioxide storage tank.
 26. The method as claimed in claim 22wherein gaseous carbon dioxide in the separation vessel is recycledthrough a carbon dioxide recovery pipeline and directly injected in aseparate pipeline in parallel operation.
 27. The method as claimed inclaim 26 wherein the impurity concentration in said recycled carbondioxide is lower than 20%.
 28. The method as claimed in claim 18 whereinwater is recycled from the separation vessel and is aerated by a gasselected from the group consisting of air, nitrogen, methane, carbonmonoxide and argon.
 29. The method as claimed in claim 28 wherein therecycled water from the separation vessel is heated to a highertemperature by injection of steam or other heating methods before reuse.30. The method as claimed in claim 1 wherein carbon dioxide is mixedwith a water stream before being injected in the pipeline.
 31. Themethod as claimed in claim 30 wherein the volumetric flow rate ratio ofsaid carbon dioxide to said water is from 1:0 to 20:1.
 32. The method asclaimed in claim 31 wherein the temperature of the water is from 1° C.to 100° C.
 33. The method as claimed in claim 1 wherein carbon dioxideis injected in the pipeline at several points.
 34. The method as claimedin claim 33 wherein the distance between two adjacent injection pointsis from 1 meter to 500 meters.
 35. The method as claimed in claim 33wherein the number of said injection points is from 2 to
 20. 36. Themethod as claimed in claim 33 wherein the injection rates of carbondioxide will be the same or different at said several points.
 37. Themethod as claimed in claim 30 wherein the volumetric flow rate ratio ofthe carbon dioxide to the water in the oil-bearing formation is from0.2:1 to 15:1.
 38. The method as claimed in claim 37 wherein thevolumetric flow rate ratio of the carbon dioxide to the water in theoil-bearing formation is from 0.5:1 to 10:1.